Thermal enhanced oil recovery (TEOR) is an established practice known in the applicable art. TEOR is a subset of the general field of enhanced oil recovery (EOR), which also includes gas injection and oil formation flooding with non-heated water. In practice, TEOR includes steam injection and hot water flood. The TEOR practice is generally employed in heavy oil regions, where the in-place oil's viscosity is too high to be efficiently recovered by pumping or other EOR practices. In TEOR, steam (or hot water) is injected into the oil formation through an injection well. The injected steam transfers heat to the oil and promotes TEOR through a number of processes: heating the oil lowers its viscosity, improving its mobility; thermal expansion; steam distillation; and miscible processes. The oil is then recovered by hydrodynamic action with the injected fluid via flood-through or flow-back action.
Flood-through is used when the formation fluids are recovered at a production well other than the injection well. Flow-back is used when the injection well and the production well are the same, e.g., “huff and puff” steam injection, where steam is injected into the oil formation, allowed time to condense and heat the formation oil, and then recovered as liquid by back-flowing the injection well. In either case the basic principle is to inject hot fluid into an oil formation, promoting TEOR, and then recover that oil with the recovered injection fluids. The conventional practice for supplying the heat energy for TEOR steam flooding is typically accomplished by burning gas or oil, or in some cases in a cogeneration fashion, i.e., using the heat rejected from a power plant. In certain areas, TEOR practices include discarding the produced fluids, less the separated oil and gas, in subterranean formations.
The invention disclosed herein provides the heat for TEOR from Geopressured-Geothermal energy. Geopressured-Geothermal (GPGT) energies are contained in the reservoir brines of certain sedimentary basins, unlike Geothermal energies which are associated with volcanic hot-rock. The GPGT reservoir brines are highly pressured and hot, with values ranging 1000 to 4000 psi flowing surface pressure and 250 to 500° F. respectively. The brines are entrained with natural gas, varying 20 to 100 scf/bbl. The brines can be recovered via typical well-bores, at high flow rates ranging 15,000 to 40,000 bbl/day. The available energies are: (1) the mechanical energy of the high pressure flowing brine; (2) the thermal energy via heat exchange with the hot brine; and (3) the chemical energy of the natural gas which can be withdrawn from the brine in a standard gas separator. The GPGT brines' water and salts are additional resources. The amount of salts and minerals dissolved in the GPGT reservoir brines, or Total Dissolved Solids (TDS), varies over a wide range: 3500 to 200,000 mg/l. The TDS are comprised of mostly Sodium Chloride, with lesser amounts of Calcium, Potassium, and other trace elements.
Generally there is an inverse relationship between brine TDS and brine gas content as the solubility of gas in water decreases with increasing salinity. There are at least seven known GPGT basins in the U.S. and about 60 others worldwide (Dorfman, 1988). The largest U.S. GPGT basin is in the Gulf Coast region with the second largest in the Central Valley of California. The U.S. Department of Energy (DOE) initiated the Geopressured-Geothermal Research Program in 1974 to define the magnitude and recoverability of GPGT energy in the U.S. Under this program, five deep GPGT research wells were flow tested in the Texas-Louisiana Gulf Coast region from 1979 to 1992. These flow tests demonstrated GPGT reservoir production longevity, ranging 5 to 7 years at sustained flow rates of 20,000 to 40,000 bpd (Negus-de Wys, et al, 1990; Riney, 1991; Riney, 1993). The specifics of the GPGT reservoir drive mechanism(s) have been debated (e.g., fault-enhanced fluid communication, shale dewatering, etc.) but it's widely accepted that the GPGT basins have outperformed conventional reservoir models (Ramsthaler, et al, 1988; Riney, 1988; John, 1989). The DOE ended funding for the GPGT program in 1992 and the last of the DOE test wells was plugged in December, 1993 (Rinehart, 1994).
California and Texas contain 32% and 31% respectively of the nation's 1108 heavy oil reservoirs (10<API°<20). The Kern County, Calif. region alone is estimated to have 18 billion bbls heavy oil (Negus de-Wys, et al, 1991). In Texas, the Jackson-Yegua Barrier/Strandplain Sandstone is estimated to have 1.13 billion bbl original in-place oil (OOIP), of which 249 million bbls is considered recoverable (Seni, et al, 1993). Typical recovery efficiencies for unassisted medium-heavy oil in Texas range from 10% to 30% (Kimmell, 1991). Consequently, most of the in-place heavy oil remains a target of opportunity for TEOR. Likewise clean air requirements (typically 1 bbl oil-burn required for 3-4 bbl recovered oil; CA no longer allows oil-fired TEOR due to air quality) and recovery costs (e.g., $13/bbl for Kern County TEOR, c.1996 costs per EPRI, 1999) serve to impede conventional access to heavy oil reserves in the U.S.
This information is noted here to the greatest import to underscore the potential, and national importance, of the invention's TEOR method proposed herein; improved access to existing domestic reserves will have the same near-term effect of reducing our reliance on foreign oil. Additionally, the method proposed herein, as it interfaces with U.S. Pat. Re. 36,282 (Nitschke, 1999), provides for the efficient management of the GPGT brine end-salt, the lack of which management function(s) would inhibit full recovery of the GPGT potential.
Alameddine, in U.S. Pat. No. 4,986,352 (1991), teaches a method for intermittent steam injection which improves the vertical sweep efficiency for multi-layered oil sands. Alameddine reports model simulations showing steam/oil ratios improving from 4.6 bbls steam required per bbl oil recovered to only 2.7 bbls steam required per bbl of oil.
Goldsberry, in U.S. Pat. No. 4,824,447 (1989) teaches recovering GPGT brine from a wellbore for direct injection into oil reservoirs after it has been degassed in a high pressure separator, or combined with treated (surfactant/polymer) brine from a low pressure separator and then injected. The injection brine can also be treated with CO2 rich gas, which has been separated from the brine via a high-pressure membrane or low pressure separator. Part or all of the GPGT brine can be diverted to a turbine to produce electricity. The post turbine brine is then degassed in a high-pressure gas separator and then transfers heat to an organic Rankine cycle (ORC) for further power production. The thermally spent brine from the ORC is passed to a low-pressure gas separator, where CO2 rich gas is withdrawn. The high pressure separator gas is routed to a membrane where quality gas is removed for sale and CO2 rich gas is sent to combine with the low pressure separator gas for burn in an engine to drive a generator. The exhaust gas from the engine transfers superheat to the ORC. All spent brine is discarded to a disposal well in a suitable aquifer.
Jones, in U.S. Pat. No. 4,319,635 (1982) teaches that recovered brines can be processed, much in the same way as suggested by Goldsberry, and used directly for TEOR injection fluid. Jones further teaches that the gas separated from the brine can be used to heat the same brine prior to injection, or injected with the TEOR fluid and recovered after the TEOR operation is complete. He further teaches that raising the pore fluid pressure via injection of EOR and TEOR fluids increases porosity and permeability by mechanically expanding the pores. As in Goldsberry, Jones discards all the return TEOR blowdown to a disposal well in a suitable aquifer. Additionally, Jones teaches using straddle packers in the injection well to direct the injection fluid to higher and lower perforations across the oil formation as desired.
Marberry and Coutret, in U.S. Pat. No. 3,572,4375 (1971) teach stepwise steam injection into an injection well(s) across an oil formation with recovery in a production well(s). The steam injection is stepwise in the sense that [1] the steam is injected; [2] followed by hot water at the same temperature as the steam; and [3] lastly it's displaced to the production well(s) via cold water flood. Marberry and Coutret note that the available waters for steam flood in the oil field typically limit the injection steam's quality to 80% so as to prevent deposition of solids in the boiler equipment.
Walter, in U.S. Pat. No. 2,823,752 (1958), teaches a method for injecting steam and combustion gases for TEOR. Walter's method utilizes an internal combustion engine mounted on a common shaft with a turbine for injecting the TEOR fluid, compressors for pressurizing air and gas into a combustion chamber mounted on the surface, and a pump to feed water into the combustion chamber, where it is generated into steam for injection via the turbine. The method further utilizes the waste heat from the internal combustion engine, i.e., that to heat extracted to cool the engine as well as the sensible heat from the exhaust gas.
Schlinger, in U.S. Pat. No. 4,007,786 (1977), teaches the conventional practice for TEOR of steam production from a co-generation operation (shaft power for electricity with waste heat used for steam production), with particular focus on treating the gaseous fuel from a hydrocarbonaceous feedstock, preferably provided by the produced oil, to limit stack pollutants.
The methods taught by Clark (U.S. Pat. No. 4,458,756; 1984), Fleming (U.S. Pat. No. 4,699,213; 1987), and Horton, et al (U.S. Pat. No. 5,458,193; 1995), refer to the so called in-situ combustion methods, wherein a fuel supply and oxidation means are injected downhole into the oil bearing formation (or below in an adjacent formation per Clark) and ignited, by direct action or spontaneously. Water is typically injected downhole as feedstock for steamflood, the heat of which steam generation is provided by the downhole combustion.
Kobro, in U.S. Pat. No. 6,205,289 (2001) teaches a steam generation method for TEOR that uses a system of distributed electric boilers. Kobro notes the method will incur less thermal loss from that of conveying steam from a centralized generator, and that environmental issues regarding the emissions from in-field fuel burn will be largely circumvented.
Heins, in U.S. Pat. No. 7,150,320 (2006) teaches a method(s) for treating recovered TEOR fluid water for reuse in a boiler to generate TEOR steamflood. In his method(s), Heins aims to minimize the amount of blowdown (disposed), reduce the required processes for pre-treating TEOR boiler water, and improve water purity for boiler functioning.
Much of the work by the DOE's GPGT Industrial Consortium participants involved using GPGT brines for TEOR (Negus-de Wys, et al, 1991; Seni, et al, 1991, 1993; Hamlin, et al, 1991; and Kimmell, 1991), namely via direct flooding with the hot GPGT brine. In regard to the primary technical field of the instant invention, the TEOR method proposed herein is distinguished from that earlier work, as well as from conventional TEOR practice, in that it: (1) uses the gas produced from the GPGT brine to fire a power cycle to compresses low pressure steam for TEOR (e.g., Multi-Effect Distillation end-effect steam from a GPGT conversion system); (2) can reuse the TEOR fluid after separating the oil, versus disposal; (3) initiates and replenishes the TEOR fluid volume with steamflood rather than the GPGT brine itself; and (4) optionally uses the gas for TEOR process heat after being passed once through the oil reservoir under recovery and recovered at the oil separator, further enhancing oil recovery. Also the rate of TEOR fluid injection for the disclosed invention is more independent from the GPGT production rate than the direct brine-flood method. As the amount of recovered oil is directly related to the injection rate, this feature will allow for adjustments to site-specific factors and enable better control of the TEOR process while affording similar systems flexibility to the GPGT recovery and conversion systems (i.e., per Nitschke, U.S. Pat. Re. 36,282). These differences are key in cutting costs (disposal of TEOR fluids, pure water for steam generation) and operational difficulties (oil reservoir plugging by GPGT brine solids), in addition to improving the recovery efficiency via steamflood, versus brine flood, and gas entrainment. For comparison, Negus de-Wys, et al (1991) use a GPGT hot brine flood TEOR ratio of 20:1, i.e., 20 bbls hot brine flood to 1 bbl recovered heavy oil; the method discussed herein shows the potential to increase this TEOR production efficiency by a factor of 2 to 3, i.e., for equivalent GPGT production rates.
Concerning the second field related to the instant invention, salt recovery from sea water or brines via salt ponding, evaporation ponds for such purpose are an established practice. Typically, shallow ponds are filled with sea water and then the water is allowed to evaporate leaving behind solid sea salts that can be harvested. Spray evaporation ponds (SEP) utilize pump driven discharge nozzles exhausting over the pond surface to increase the surface area available for evaporative mass transfer; the driving potential for the mass transfer process is the difference between the vapor pressure of the discharging fluid and the water vapor pressure in the local air. Likewise, SEPs are in wide use for cooling, say, for heat rejection from power plants, although cooling towers are generally the preferred practice. The use of SEPs for salt recovery, while unknown to the author in practice, have been suggested by others (Lof, et al, 1972). However the invention disclosed herein is unique in its method of thermally charging the SEP process via waste heat from a brine distillation process. Brandt, et al (U.S. Pat. No. 5,695,643) teach a method for reducing recovered oil field waters, that require ultimate disposal, by use of a reverse osmosis unit coupled with a combustion heat evaporator, which is likewise distinguished from the present invention's use of SEPs.
The interfacing technology to this invention is found in U.S. Pat. Re. 36,282 (Nitschke, 1999), which best describes that aspect of the presently proposed method since that system is an integral part of the invention disclosed herein. Nitschke teaches producing GPGT brines through a well bore, flowing the brine to a hydraulic turbine for power generation, separating the gas, and then routing the brine to a multi-effect distillation unit for separating the GPGT source brine into saturated brine and distilled water end-products. Nitschke further teaches utilizing the saturated brine end-product for the large scale construction of solar ponds.
Within the applicable art, neither Marberry and Coutret (U.S. Pat. No. 3,572,4375; 1971) nor Alameddine (U.S. Pat. No. 4,986,352; 1991) provide discussion regarding a particular method for producing the steamflood, but rather teach enhancements to TEOR efficiency; whereas the instant invention illustrates a novel manner for producing said steamflood. Also the methods of Heins (U.S. Pat. No. 7,150,320; 2006) only address processes for treating recovered TEOR fluids purity in preparation for reuse as steamflood via a boiler, versus a specific TEOR steam generation method as taught in the present invention. Additionally, the present invention is distinguishable from the methods taught by Goldsberry (U.S. Pat. No. 4,824,447) and Jones (U.S. Pat. No. 4,319,635) as the GPGT brine is not used directly for the TEOR fluid, but only the water and steam extracted from the brine in a distillation process. Also, to further distinguish from Goldsberry, the option for gas injection with steamflood in the instant invention utilizes the CH4-rich GPGT gas, versus CO2-rich post-separation gas, and further utilizes the gas for TEOR process energy post recovery from the oil reservoir. Walter (U.S. Pat. No. 2,823,752) utilizes a combustion chamber on the surface to form steam and gas for TEOR by direct contact, which is clearly distinguished from the TEOR method of the instant invention, which utilizes the byproduct heat energies recovered from GPGT brine in a GPGT conversion system. The conventional co-generation steam production method, e.g., of Schlinger (U.S. Pat. No. 2,823,752), which likewise utilizes waste heat from a gas turbine to produce steam for TEOR, is distinguished from the instant invention which primarily utilizes the gas turbine (and other heat-engine cycles) to compress low-pressure steam, for TEOR injection, from a GPGT conversion system that is used to recover and convert GPGT energy for TEOR and other beneficial uses. The in-situ combustion TEOR methods taught by Clark (U.S. Pat. No. 4,458,756; 1984), Fleming (U.S. Pat. No. 4,699,213; 1987), and Horton, et al (U.S. Pat. No. 5,458,193; 1995) are obviously distinguished from the present invention, but were included to provide a wide background art. Likewise the use of electric boilers for steam generation, as taught by Kobro (U.S. Pat. No. 6,205,289; 2001), is clearly distinguished from the instant invention's use of a GPGT conversion system and products to facilitate TEOR steamflood.
The inventor believes the known prior art taken alone or in combination neither anticipate or render obvious the present invention. Reference to the foregoing materials does not constitute an admission that such disclosures are relevant or material to the present claims. Rather, such materials relate only to the general field of the disclosure and are cited as constituting the closest art of which the inventor is aware.